Delayed gelation of polymers

ABSTRACT

The disclosure is directed to methods and compositions delaying the gelation of polymers in water flooding by sequentially or co-injecting a carboxylate-containing polymer solution, a gel-delaying polymer, and gelation agent into a hydrocarbon reservoir. Delays of weeks are observed.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of allowed U.S. patent applicationSer. No. 17/079,877, filed Oct. 26, 2020 (US Patent ApplicationPublication No. US20210054260), which is a division of U.S. patentapplication Ser. No. 14/847,734, filed Sep. 8, 2015 (U.S. Pat. No.10,851,286), which claims the benefit of U.S. Provisional ApplicationNo. 62/081,950, filed on Nov. 19, 2014. Each is incorporated byreference in its entirety herein for all purposes.

FEDERALLY SPONSORED RESEARCH STATEMENT

Not applicable.

REFERENCE TO MICROFICHE APPENDIX

Not applicable.

FIELD OF THE DISCLOSURE

This disclosure relates to compositions and processes for oil fieldapplications. More specifically, the disclosure relates to delayinggelation of carboxylate-containing polymer solutions commonly used inenhanced oil recovery under reservoir conditions.

BACKGROUND OF THE DISCLOSURE

The challenge for all oil and gas companies is to produce as much oil ascommercially feasible, leaving as little oil as possible trapped andwasted inside the reservoir. During the primary recovery stage,reservoir drive comes from a number of natural mechanisms. These includenatural water pushing oil towards the production well, expansion of thenatural gas at the top of the reservoir, expansion of gas initiallydissolved in the crude oil, and gravity drainage resulting from themovement of oil within the reservoir from the upper regions to lowerregions where the wells are located. Recovery factor during the primaryrecovery stage is typically about under such natural drive mechanisms.

Over the lifetime of the well, however, the pressure will eventuallyfall, and at some point there will be insufficient underground pressureto force the oil to the surface. Once natural reservoir drivediminishes, enhanced recovery techniques are applied to further increaserecovery.

Most enhanced recovery methods rely on the supply of external energyinto the reservoir in the form of injecting fluids to increase reservoirpressure, hence replacing or increasing the natural reservoir drive withan artificial drive, and to sweep or displace the oil from the reservoirand push it towards the oil production wells. In addition, pumps, suchas beam pumps, gas lift assisted pumping and electrical submersiblepumps (ESPs), can be used to bring the oil to the surface.

Enhanced recovery techniques include increasing reservoir pressure bywater injection, CO₂ injection, natural gas reinjection, and miscibleinjection (MI), the most common of which is probably water injection.Typical recovery factor from water-flood operations is about 30%,depending on the properties of oil and the characteristics of thereservoir rock. On average, the recovery factor after primary andsecondary oil recovery operations is between 35 and 45%.

While enhanced recovery techniques are quite effective, the existence offractures and highly porous or permeable regions reduces theireffectiveness. Any gas or liquid that is injected into a well willnaturally travel the least restrictive route, thus bypassing most of theoil in the less porous or less permeable regions. Thus, the overalleffectiveness of the sweep is reduced by these so-called “thief zones,”which channel injection fluid directly to production wells.

In such cases, polymers, foams, gelants, emulsions and the like areinjected into the thief zones in order to block these zones, thusdiverting the subsequent injection fluids to push previously unswept oiltowards the production wells. See e.g., FIG. 1A-B.

Among the polymers used for such purposes, partially hydrolyzedpolyacrylamide (HPAM) crosslinked with Cr (III) gels have been widelyused for water shutoff and sweep improvement in field applications.Polymer gels have been applied in enhanced oil recovery to improve thesweep efficiency, prolong the life of an oil well and maximize therecoverable oil amount by placing the gelants deep into the reservoirand blocking the high-permeability channels.

One of the difficulties with the use of polymers to block thief zones isthe issue of viscosity. Viscous polymers are difficult to pump and, inpresence of common crosslinking agents such as chromic acetate, gel tooquickly to place deep in target zones. For this reason, there isconsiderable effort directed to delaying the crosslinking of polymersuntil they have already penetrated deep into the oil bearing reservoirs.

Many efforts have been directed to delaying the gelation of suchpolymers by adding a gelation delaying agent to the compositions. Theuse of ligands complexed with multivalent cations such as Al(III),Cr(III), Ti(IV) and Zr(IV) to crosslink partially hydrolyzedpolyacrylamides has been a common practice to slow the rate of reactionsof these cations with HPAM. The presence of ligands such as acetate,citrate, propionate, malonate, etc., which bind to multivalent cations,inhibit rapid interaction of the multivalent cations with the negativesites of HPAM to produce gels, thus delaying the rate of gelation.Fracture treatments in injection wells have been quite successful,especially when large treatment volumes are used. That is because lesstime is required for placement of gels in the fractures.

An extensive study (Albonico 1993) performed on evaluating variousretarding ligands, ranked the effectiveness of hydroxycarboxylates,dicarboxylates and aminocarboxylates on retarding the gelation rate ofCr(III) with HPAM solutions. This study showed that malonate ions are 33times slower than acetate to gel 0.5% HE-100, a copolymer of acrylamideand sodium AMPS, at 120° C. This study ranked ascorbate to be 51 timesslower than acetate under the same conditions. The authors furthertested the effectiveness of various ligands in propagation of Cr(III)ions in both sandstone and carbonate formations. They concluded thatmalonate ions are most effective in promoting propagation of Cr(III) inporous media, preventing precipitation and thus retention of Cr(III).

While the rates of gelation of HPAM with complexes of multivalentcations are slower than for un-complexed multivalent cations, they arestill not slow enough. Extensive gelation tests with complexes ofmultivalent cations with HPAM indicate formation of non-flowing gelswithin a few hours, not long enough for deep placement of the gelants inhigh permeability thief zones, before reaching the non-flowing stage.Additionally, the integrity of the stabilized package due tochromatographic separation might hinder their effectiveness of suchsystems in treating high permeability targets deep in porous mediamatrix.

Extending the gelation times from a few hours to days or weeks, istherefore, highly desirable for the placement of the gelants deep inmatrix target zones. Further, a less toxic package that is very stablein various brines and at typical reservoir temperatures would also bedesirable, since the increased stability will allow deeper deployment.

Thus, what is needed in the art is a method for slowing the delayingtime of polymer systems commonly used in oil field applications. In theideal case, the gelation will be delayed by a few weeks to allow fordeep penetration of gelants in the reservoir matrix. Additionally,techniques using environmentally friendly components are highlydesirable for placement of gels deep into the reservoir matrix.

SUMMARY OF THE DISCLOSURE

The disclosure teaches the delayed formation of gels comprising polymersand crosslinkers commonly used in oil field applications by changing theorder of injection.

Typically, carboxylated polymers and the gelling agent or crosslinkerare injected into the reservoir together or in alternating slugs. Theaddition of e.g. Cr(III) chloride to carboxylated polymers such as HPAMor B29 (an expandable microparticle form of HPAM) under similarconditions result in instant gelation or precipitation. The currentstate of art gelling system in which Cr(III) acetate or propionate areused to crosslink with HPAM solutions occur within a few hours at 40° C.This gelation time is too short to inject such gelant compositions deepinto the matrix of oil-bearing formations, thus impeding deep reservoirdeployment.

US20140202693 discloses a delayed gelling system which uses adi-carboxylated polymer such as polyaspartate (“PAsp”) and polyvinylalcohol succinate (“PVAS”) to complex multivalent metal ions such asCr(III) in a degradable nanogel. This nanogel is then co-injected withcarboxylated polymer solutions into the reservoir. The labile bonds inPAsp and PVAS break over time, slowly releasing the multivalent metalions, and allowing them to crosslink with the anionic sites of theco-injected carboxylated polymers to produce gels and block highpermeability channels.

The present method improves upon US20140202693 by changing the order inwhich the components are added to achieve the same or better delayedgelling without forming a separate nanogel. In the presently disclosedmethod, a carboxylated polymer solution, at least one gel-delayingpolymer, and a crosslinker are injected sequentially into an in-linemixer connected to an injection well. The resulting mixture is thenpumped further into the reservoir. Thus, unlike US20140202693, time issaved by not forming a separate composition before injection.

The gelation time for the present method is generally longer than about3 days, 5 days, 7 days, 10 days, 30 days or more, depending ontemperature, crosslinkable polymer composition and concentration.Typical gelation times are 7-45 days, depending on temperature. Gelationtime has been extended to at least 35 days at 85° C. before anon-flowing gel is set.

We have exemplified the gel-delaying polymer herein using PVAS and PAsp,but it is likely that many other molecules with similar chemistry couldbe used. Thus, any di- or tri-carboxylate that can be dehydrated to forman anhydride can be conjugated to polyvinyl alcohol (PVA) using similarchemical reactions. Thus, maleic anhydride (cis-butenedioic anhydride),is expected to be substitutable in the invention, as are glutaricanhydride, phthalic anhydride, oxalic anhydride, etc. Further, any di-or tri-carboxylate can be polymerized and used, based on our successwith polyaspartate.

Though we used PVA as a base polymer to add the succinate to, anypolymer containing double bonds (such as vinyl, allyl, styrene,acrylamide, etc.) can be conjugated to e.g., succinate anhydride.

Carboxylate-containing polymers suitable for use in this invention arethose capable of gelling in the presence of a crosslinking agent such aschromium or zirconium, and are preferably stable at reservoirconditions. Polymers suitable for use in this invention, include, butare not limited to, polysaccharides, such as carboxylatedpolysaccharides or carboxylated guar, cellulose ethers, such ascarboxymethyl cellulose, and acrylamide-containing polymers.

HPAM was used herein as an exemplary polymer, but any acrylate-basedpolymer can also be used, provided there are sufficient, unhinderedcarboxylate groups available for the metal ion crosslinking reaction.Preferred polymers include those containing e.g., acrylamide, tert-butylacrylate, acrylamido-2-methylpropane sulfonic acid, sodium2-acrylamido-2-methylpropane sulfonate (NaAMPS), N,N, dimethylacrylamide, and copolymers thereof. Other polymers includepolysaccharide-based polymers, such as carboxylated guar orcarboxymethyl cellulose. Furthermore, microparticles thereof that arecapable of swelling or “popping” in situ can be used in the presentmethods. Preferred microparticles have 1-90% sodium acrylate, preferable1-60% and most preferable 2-20%.

Other suitable acrylamide-containing polymers that also contain pendantcarboxylate groups via which crosslinking can take place are disclosedin U.S. Pat. No. 3,749,172 (herein incorporated by reference in itsentirety for all purposes).

Thermally stable carboxylate-containing polymers of acrylamide, such asterpolymers of N-vinyl-2-pyrrolidone and acrylamide and sodium acrylate;tetrapolymers of sodium-2-acrylamido-2-methylpropanesulfonate,acrylamide, N-vinyl-2-pyrrolidone and sodium acrylate; terpolymers ofsodium-2-acrylamido-2-methylpropanesulfonate and acrylamide and sodiumacrylate; terpolymers of N,N dimethylacrylamide and acrylamide andsodium acrylate; and combinations of any two or more thereof, areparticularly preferred for applications in high salinity environments atelevated temperatures for stability.

Selected carboxylate-containing terpolymers also are useful in thepresent process, such as tetrapolymers derived from acrylamide, sodiumacrylate, and N-vinyl-2-pyrrolidone and N,N-dimethylacrylamideco-monomers with lesser amounts of monomers such as vinyl acetate,vinylpyridine, styrene, methyl methacrylate, and other polymerscontaining acrylate groups. While exemplified with a sodium counter ion,these polymers can be associated with any counter ion including, but notlimited to, potassium cations, silver cations, quaternary ammoniumcations and the like.

According to the present disclosure, the molecular weight of thecarboxylate-containing polymers is generally at least about 1,000 Da andless than about 30,000,000 Da. However, polymers of any size areexpected to be amenable with the present methods with slightmodifications to the associated gel counterparts.

The mole percent % of the carboxylate group in carboxylate-containingpolymers, such as partially hydrolyzed polyacrylamides (HPAM) isgenerally in the range of from about to 100, preferably about 0.1 toless than about 55, more preferably about 1 to less than about or about40 to 50.

Suitable crosslinkers include multivalent metal ions include chromium,zirconium, titanium, aluminum and the like. The metal ions can also becomplexed with a ligand, such as acetate, propionate, malonate, citrateand the like. Other cationic crosslinkers such as polyethylenimine (PEI)could be used.

The presently preferred multivalent metallic compound is selected fromthe group consisting of zirconium compounds, titanium compounds,aluminum compounds, iron compounds, chromium compounds, such as Cr(III)chloride, Cr(III) acetate, Cr(III) propionate, and combinations of anytwo or more thereof. Examples of suitable multivalent metallic compoundsinclude, but are not limited to, sodium zirconium lactate, potassiumzirconium lactate, ammonium zirconium lactate, ammonium zirconiumcarbonate, sodium zirconium carbonate, potassium zirconium carbonate,ammonium zirconium fluoride, ammonium zirconium chloride, zirconiumammonium citrate, zirconium chloride,tetrakis(triethanolamine)zirconate, zirconium carbonate, zirconylammonium carbonate, ammonium titanium carbonate, titanium chloride,titanium carbonate, ammonium titanium chloride, and combinationsthereof. These compounds are commercially available. The presently mostpreferred crosslinking agents are Fe(III) chloride, Fe (III) sulfate,Al(III) chloride or Al(III) sulfate, zirconium chloride, chromium (III)chloride, and the like. Even more preferred are zirconium lactate andchromium (III) chloride.

The concentration of crosslinking agent used in the present inventiondepends largely on the concentrations of polymers in the composition andthe desired gelation delay. Lower concentrations of polymer, e.g.,require lower concentrations of the crosslinking agent. Further, it hasbeen found that for a given concentration of polymer, increasing theconcentration of crosslinking agent generally substantially decreasesthe time of gelation (increases the gelation rate).

The concentration of crosslinking agent in the injected slug variesgenerally over the broad range of about 1 mg/l (ppm) to about 1,000 ppm,preferably over the range of about 5 ppm to about 500 ppm, and mostpreferably 5 ppm to 200 ppm based on Cr(III).

In addition to the crosslinkers, gel-delaying polymers, polymers andinjection fluids described herein, the injection fluid may also containother conventional additives including chelating agents to removepolymerization inhibitors, pH adjusters, initiators and otherconventional additives, accelerators, retardants, corrosion inhibitors,scale inhibitors, biocides, fluid loss additives, and the like, asappropriate for the particular application. In addition, chemicals canbe added that will reduce the adsorption of gelation chemicals to theoil reservoir.

An improved method of sweeping a reservoir is also provided herein,wherein an injection fluid is injected into a reservoir to mobilize andproduce oil, the improvement comprising injecting, in order, acarboxylate-containing polymer, at least one gel-delaying polymer and acrosslinker plus a fluid into a reservoir, aging said carboxylatepolymer, at least one gel-delaying polymer, crosslinker and fluid toincrease its viscosity, injecting additional injection fluid into saidreservoir to mobilize oil, and producing said oil. The aging time can bevaried, as described herein, to allow compete penetration of thereservoir.

Typically, a solution of the carboxylate-containing polymer, thegel-delaying polymer and metal ionic crosslinker are mixed in-linebefore being pumped into the subterranean formation, followed by waterto displace the solution from the well bore to prevent gelling at thewellbore. Alternatively, the carboxylate-containing polymer and thegel-delaying polymer can be injected and displaced by water before themetal ionic crosslinker is injected.

The nature of the subterranean formation is not critical to the practiceof the processes described herein. The delayed gel-forming compositioncan be injected into said subterranean formation having a temperaturerange of from about 10° C. to about 180° C. Any means known to oneskilled in the art such as, for example, pumps, can be used forinjecting said gel-forming composition.

Another embodiment is a method of improving sweep efficiency of a fluidflood of a reservoir, said method comprising sequentially injecting thecompositions herein described (plus polymer and fluid as needed) into areservoir; aging the composition, e.g., 30-40 days or as needed, toincrease its viscosity; injecting an injection fluid into said reservoirto mobilize the oil; and producing said mobilized oil.

Any suitable procedure for preparing the aqueous admixtures of thegellable polymers, dicarboxylate polymers, and liquid can be used. Someof the polymers can require particular mixing conditions, such as slowaddition of finely powdered polymer into a vortex of stirred brine,alcohol pre-wetting, and protection from air (oxygen), preparation ofstock solutions from fresh rather than salt water, as is known for suchpolymers.

As used herein, ppm refers to weight ratio in parts per million, basedon total weight.

The term “polymer” refers to a molecule built up by repetitive bondingtogether of smaller units called monomers. The polymer can be linear,branched network, star, comb, or ladder types of polymer. The polymercan be a homopolymer in which a single monomer is used or can becopolymer in which two or more monomers are used. Types of copolymersinclude alternating, random, block, and graft.

The term “carboxylate-containing polymer” used herein refers to, unlessotherwise indicated, a polymer that contains a plurality of freecarboxylic acid groups or carboxylate groups in which the proton of thecarboxylic acid is substituted with an ammonium ion, an alkali metalion, an alkaline earth metal ion, or combinations of any two or morethereof, such that the pendant carboxylate groups can be crosslinkedwith a multivalent metal ion, thus forming a gel.

The term “gelation time” is defined as the time when the viscosity ofthe gel solution increases abruptly to a value greater than 1000 cP(100% scales) at a shear rate of 2.25 s⁻¹.

The use of the word “a” or “an” when used in conjunction with the term“comprising” in the claims or the specification means one or more thanone, unless the context dictates otherwise.

The term “about” means the stated value plus or minus the margin oferror of measurement or plus or minus 10% if no method of measurement isindicated.

The use of the term “or” in the claims is used to mean “and/or” unlessexplicitly indicated to refer to alternatives only or if thealternatives are mutually exclusive.

The terms “comprise”, “have”, “include” and “contain” (and theirvariants) are open-ended linking verbs and allow the addition of otherelements when used in a claim.

The phrase “consisting of” is closed, and excludes all additionalelements.

The phrase “consisting essentially of” excludes additional materialelements, but allows the inclusions of non-material elements that do notsubstantially change the nature of the invention.

The following abbreviations are used herein:

Abbreviation Meaning PAsp Polyaspartate PEl Polyethylenimine PVApolyvinyl alcohol PVAS polyvinyl alcohol succinate MW Average molecularweight HPAM Hydrolyzed Poly-Acrylamide, partially hydrolyzedpolyacrylamide DS Dextran sulfate RO Reverse osmosis AC24 Alcomer ® 24B29 Microparticle of 5 mole % sodium acrylate and 95 mole % acrylamide

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A Water flooding wherein water bypasses oil, travelling the thiefzones. FIG. 1B The thief zones can be blocked by polymeric gels, foamgels, and the like, thus forcing water to sweep the reservoir andproducing more of the original oil in place.

FIG. 2 . Complex formation of HPAM/B29 with PAsp/PVAS and Cr(III).

FIG. 3 . Gelation of AC24, PAsp, and CrCl₃ in Synthetic Brine A at 120,100, and

FIG. 4 . Gelation of B29, PAsp, and CrCl₃ in Synthetic Brine B at 120,100, and

FIG. 5 . Gelation of AC24, PVAS, and CrCl₃ in Synthetic Brine A at 85and 65° C.

FIG. 6 . Gelation of B29, PVAS, and CrCl₃ in Synthetic Brine B at 85 and65° C.

DETAILED DESCRIPTION

The disclosure provides a novel method that delays gelling under theconditions typical of water flooding in situ and have particular utilityin blocking thief zones of reservoirs, but other uses are possible,especially in the agriculture, remediation and drug delivery arts.

In one embodiment, the method involves sequentially injecting acarboxylate-containing polymer, a gel-delaying polymer, and acrosslinker into the reservoir. This injection sequence negates the needto form a separate nanogel comprising the gel-delaying polymer and acrosslinker, as seen in similar art. By adding the gel-delaying polymerbefore the crosslinker, delays the gelation from days to weeks, allowingfor deeper reservoir penetration.

The sequential injection can be followed by injection of fluids todisplace the gelling composition or recover hydrocarbons. Alternatively,the carboxylate-containing polymer and gel-delaying polymer can beinjected, followed by a fluid injection, before the crosslinker isinjected.

In another embodiment, the gelant is injected as a single packagecomplex of e.g. HPAM (AC24), temporarily carboxylated polymer such aspoly(sodium aspartate) (PAsp) and/or polyvinyl alcohol succinate (PVAS),and metal ions (such as Cr(III)), as shown in FIG. 2 . When the metalion, e.g. Cr(III) is added into the mixture of HPAM and PAsp or PVAS, itwill form complexes with the carboxyl groups of both HPAM and PAsp orPVAS, which leads to a single package of HPAM, PAsp and/or PVAS, Cr(III)complexes that can be injected. When settled into the reservoir, removalof carboxyl groups of PAsp or PVAS, triggered by hydrolysis or heat,will release the Cr(III), resulting in the HPAM forming a gel withCr(III).

Molar ratios of COO⁻ from PVAS or PAsp to metal ion range from 2:1, 4:1,6:1, 10:1, 12:1; 16:1 and 20:1. Molar ratios of 6:1 to 12:1 are mostpreferred.

This composition of HPAM, PAsp/PVAS, Cr(III) complex (gelant fluid) canmove forward as a single package in underground reservoir, thusminimizing or avoiding separation occurrence during delivery inunderground reservoir. Experiments are still being conducted todetermine if the package can chromatically separate downhole.

The polymer used to delay the gelation can be made from monomersselected from the group of vinyl, allyl, styrene, and acrylamidemonomers and their derivatives, or any polysaccharide, conjugated with adi-carboxylate or having naturally appended carboxylate groups. Anydi-carboxylate (or tricarboxylate) can be used, including citrate,succinate, aspartate, glutamate, malate, oxalate, malonate, glutarate,adipate, pimelate, and the like, or a derivative thereof.

In some embodiments, the gel-delaying polymer is a polymer or copolymerof citrate, succinate, aspartate, glutamate, malate, oxalate, malonate,glutarate, adipate, pimelate, carbonate, and the like, or derivativesthereof.

In some preferred embodiments, the gel-delaying polymer comprisespolyvinyl alcohol (PVA) succinate, N-hydroxylmethyl acrylamide (NHMA)succinate, allyl alcohol succinate and allylamine succinate, PVA malate,NHMA malate, allyl alcohol malate or allylamine malate. In otherembodiments, the polymer is polyaspartate or polyglutamate, or the like.

The crosslinker is any multivalent metal ion whose presentation needs bedelayed, and for reservoir use and tertiary crosslinking. These includechromium, zirconium, iron, aluminum, and titanium ions. In somepreferred embodiments, the multivalent metal ion is Cr(III).

Any carboxylate-containing polymer can be used in the injection,provided such polymer can be crosslinked with the metal ion. Suchpolymers include, e.g., partially hydrolyzed polyacrylamide, copolymersof N-vinyl-2-pyrrolidone and sodium acrylate, tetrapolymers ofsodium-2-acrylamido-2-methylpropanesulfonate, acrylamide andN-vinyl-2-pyrrolidone and sodium acrylate; copolymers ofsodium-2-acrylamido-2-methylpropanesulfonate and sodium acrylate; andcombinations thereof.

In some embodiments, the carboxylate-containing polymer is HPAM or B29.

An improved method of sweeping a reservoir is also provided herein,wherein an injection fluid is injected into a reservoir to mobilize andproduce oil, the improvement comprising injecting, in order, acarboxylate-containing polymer, at least one gel-delaying polymer and acrosslinker plus a fluid into a reservoir, aging said carboxylatepolymer, at least one gel-delaying polymer, crosslinker and fluid toincrease its viscosity, injecting additional injection fluid into saidreservoir to mobilize oil, and producing said oil. The aging time can bevaried, as described herein, to allow compete penetration of thereservoir.

Another improved method of sweeping a reservoir is also provided herein,wherein an injection fluid is injected into a reservoir to mobilize andproduce oil, the improvement comprising injecting, in order, acarboxylate-containing polymer, at least one gel-delaying polymer and acrosslinker plus a fluid into an in-line mixer, mixing to form acomplex, injecting said complex into the reservoir followed by anoptional fluid injection to displace the complex, aging said complex andfluid to increase its viscosity, injecting additional injection fluidinto said reservoir to mobilize oil, and producing said oil.

Another embodiment is a method of improving sweep efficiency of a fluidflood of a reservoir, said method comprising sequentially injecting thecompositions herein described (plus polymer and fluid as needed) into areservoir; aging the composition, e.g., 30-40 days or as needed(depending on reservoir temperature), to increase its viscosity;injecting an injection fluid into said reservoir to mobilize the oil;and producing said mobilized oil.

Another yet embodiment is a method of improving sweep efficiency of afluid flood of a reservoir, said method comprising injecting a complexformed by a carboxylate-containing polymer, a gel-delaying polymer, anda crosslinker herein described (plus polymer and fluid as needed) into areservoir; aging the composition, e.g., 30-40 days or as needed(depending on reservoir temperature), to increase its viscosity;injecting an injection fluid into said reservoir to mobilize the oil;and producing said mobilized oil.

The following experiments were performed to monitor gelling times fordifferent compositions for use in deep oil-bearing formations. The gelsdescribed below utilized either Synthetic Brine A, listed in Table 1, orSynthetic Brine B, listed in Table 2.

TABLE 1 Composition of Synthetic Brine A Component Concentration, g/kgNaCl 22.982 KCl 0.151 CaCl₂•2H₂O 0.253 MgCl₂•6H₂O 1.071 NaHCO₃ 2.706Na₂SO₄ 0.145 Water To 1000 g

TABLE 2 Composition of Synthetic Brine B Component Concentration, g/kgNaCl 18.420 KCl 0.424 CaCl₂•2H₂O 0.550 MgCl₂•6H₂O 0.586 SrCl₂•6H₂O 0.061NaHCO₃ 3.167 Na₂SO₄ 0.163 Water To 1000 g

Several gelation tests were performed on the various gel made herein todemonstrate the suitability of the injection order with delayed gelationtimes. Brookfield Digital Viscometer Model LVDV-II+PCP was used tomonitor the viscosity changes of gelant and control solutions anddetermine the gel time of the gelant solutions. The gelation process wasmonitored as a function of time starting from the point of visualhomogeneous dispersion. The gelation time was defined as the time whenthe viscosity of the gel solution increases abruptly to a value greaterthan 1000 cP (100% scales) at a shear rate of 2.25 s′. The temperatureof the viscometer was controlled at the stated temperatures during themeasurements.

Gelation of AC24, PAsp and CrCl₃

A solution of Alcomer® 24 (AC24), the HPAM source, containing PAsp wasprepared through mixing AC24 and PAsp, followed by addition of CrCl₃, inSynthetic Brine A while stirring.

In an oxygen-free glove box, 75.00 g of 1% of AC24 in Synthetic Brine Awas mixed with 7.73 g of a PAsp solution ([PAsp]=25.75 mg/g, pH=7.88adjusted by NaOH and HCl) in 65.30 g of deoxygenated Synthetic Brine Awith stirring.) 1.97 g of a CrCl₃ solution ([Cr(III)]=7627 ppm) wasadded into the mixture of AC24 and PAsp while stirring to obtain a finalAC24 concentration of 0.5%; final Cr(III) concentration of 100 ppm; andfinal molar ratio of COO— of PAsp to Cr(III) of 6:1.

The initial viscosity was recorded before the solution was divided into6 ml vials and incubated at 120, 100 and 85° C. The viscosities of thesamples were monitored as a function of time.

The gelation results are shown in FIG. 3 . As this figure shows, themixture of AC24, PAsp, and CrCl₃ gelled within 2, and 5 days at 120 and100, respectively. However, at the gelation was delayed by 35 days.While 85° C. is the target temperature for the analysis, this increasingdelay in time of gelation is expected for temperatures lower than 85° C.because the amide bond hydrolysis of PAsp is very slow at lowtemperature, such as 65° C.

Gelation of B29, PAsp and CrCl₃

In addition to HPAM, the delay gelation was expected to occur in asimilar polymer B29.

A sample of B29 (an expandable microparticle containing 95 mole percentacrylamide and 5 mole percent sodium acrylate, see e.g., US20140196894)in Synthetic Brine B was first prepared followed with addition of PAsp.CrCl₃ in Synthetic Brine B was then added to this mixture. The detailsof this gelation experiment are described below:

In an oxygen-free glove box, 2.50 g of 30% B29 was added into 137.09 gdeoxygenated Synthetic Brine B with 1.25 g of 30% of an invertingsurfactant while stirring. 7.01 g of PAsp solution ([PAsp]=28.03 mg/g)was added to the stirring mixture. Finally, 2.06 g CrCl₃ solution([Cr(III)]=7284 ppm) was added into the above mixture of B29 and PAspwhile stirring. Final B29 concentration was 0.5%; final Cr(III)concentration was 100 ppm; and final molar ratio of COO⁻of PAsp toCr(III) was 6:1.

As with the HPAM example above, the initial viscosity was recordedbefore the solution was divided into 6 ml vials and incubated at 120,100 and 85° C. The viscosities of the samples were monitored as afunction of time.

The results are shown in FIG. 4 . As this figure shows, the mixture ofB29, PAsp, and CrCl₃ complex gelled within 1, 8 and 33 days at 120, 100and 85° C., respectively. Again, much longer delay in gelation wasobserved at 85° C.

B29 is largely the same as HPAM once it is popped, but its degree ofhydrolysis is a bit lower (5%), thus it gels a little slower. However,both HPAM and B29 gelled in about the same time at identicaltemperatures.

Gelation of AC24, PVAS and CrCl₃

Gels using PVAS in place of PAsp were also prepared to observe thedifferences in delay gelling.

A representative single package complex, herein referred to as AC24,PVAS, Cr(III), was prepared through mixing AC24 and PVAS with Cr(III) asCrCl₃ in Synthetic Brine A while stirring. In more detail:

A stock PVAS solution was prepared through the reaction of poly(vinylalcohol, Mw 25 k, 88 mol % degree of hydrolysis) with succinic anhydrideusing triethylamine as catalyst in N-methyl-2-pyrrolidone as solventaccording to the procedure reported in the literature.⁽²⁰⁾

Stock solutions of PVAS and CrCl₃ were prepared in RO water. Theconcentration of the PVAS stock solution was 66.17 mg/g and theconcentration of the Cr(III) was 7841 ppm.

In an oxygen-free glove box, 25.00 g of 1% of AC24 was stirred intoSynthetic Brine A. 2.73 g of the PVAS stock solution in 21.64 gdeoxygenated Synthetic Brine A was added to the AC24 and stirred. 0.64 gof the CrCl₃ stock solution was added to the above mixture of AC24 andPVAS while stirring. Final AC24 concentration was 0.5%; final Cr(III)was 100 ppm; final molar ratio of COOH of PVAS to Cr(III) was 12:1.

The initial viscosity was recorded before the solution was divided into6 ml vials and incubated at 85 and 65° C. The viscosities of the sampleswere monitored as a function of time.

The results are shown in FIG. 5 . As this figure shows, the singlepackage of AC24, PVAS, CrCl₃ complex gelled within 10 and 121 days at 85and 65° C., respectively.

The difference in the experimental target values of the PVAS and PAspsystem is due to the bonds being hydrolyzed. The PVAS system controlsthe release of metal ion crosslinkers by ester bond hydrolysis, which isfaster than the amide bond hydrolysis of PAsp at the same temperature,e.g. 85° C. Thus, it is necessary to study the PVAS system at lowertemperatures to slow the hydrolysis steps. As such, cooler temperaturesare necessary to achieve larger delay times for the PVAS system.

Gelation of B29, PVAS and CrCl₃

Gels using PVAS in place of PAsp with B29 were also prepared to observethe differences in delay gelation time.

In an oxygen-free glove box, 1.67 g of 30% B29 was inverted into 90.76 gof deoxygenated Synthetic Brine A with 0.83 g of an inverting surfactantwhile being stirred. Then, 5.46 g of the PVAS solution (66.17 mg/g) wasstirred into the B29 solution. Finally, 1.28 g of the CrCl₃ stocksolution (7841 ppm) was added the above mixture of B29 and PVAS whilestirring. Final B29 concentration was 0.5%; final Cr(III) was 100 ppm;final molar ratio of COO⁻of PVAS to Cr(III) is 12:1.

The initial viscosity was recorded before the solution was divided into6 ml vials and incubated at 85 and 65° C. The viscosities of the sampleswere monitored as a function of time.

The results are shown in FIG. 6 . As this figure shows, single packageof B29, PVAS, CrCl₃ complex gelled within 10 and 93 days at 85 and 65°C., respectively.

The present invention is exemplified with respect to the above examplesand figures, however, this is exemplary only, and the invention can bebroadly applied to many polymers systems used to block thief zones inhydrocarbon recovery techniques. The above examples are intended to beillustrative only, and not unduly limit the scope of the appendedclaims.

The following references are incorporated by reference in their entiretyfor all purposes.

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The invention claimed is:
 1. A delayed gelling composition, saidcomposition made by: a) sequentially combining ingredients comprising:i) an expandable polymeric particle in an injection fluid, said particlecomprising a copolymer of about 80-98 mole percent acrylamide and about2-20 mole % sodium acrylate; ii) at least one gel-delaying polymer; andiii) a crosslinker; b) thereby forming a delayed gelling compositionwithout forming a separate nanogel.
 2. The delayed gelling compositionof claim 1, wherein said gel-delaying polymer has a gelation time of atleast 30 days at 85° C. before a non-flowing gel is set.
 3. The delayedgelling composition of claim 1, wherein said crosslinker is amultivalent metal ion selected from chromium, zirconium, iron, aluminum,and titanium.
 4. The delayed gelling composition of claim 1, whereinsaid crosslinker is polyethylenimine (PEI).
 5. The delayed gellingcomposition of claim 1, wherein said gel-delaying polymer is made frommonomers selected from the group of vinyl, allyl, styrene, andacrylamide monomers and their derivatives, conjugated with adicarboxylate or a tricarboxylate.
 6. The delayed gelling composition ofclaim 1, wherein said gel-delaying polymer is polyvinyl alcoholsuccinate (PVAS), N-hydroxymethyl N-hydroxylmethyl acrylamide (NHMA)succinate, allyl alcohol succinate and allylamine succinate, PVA malate,NHMA malate, allyl alcohol malate or allylamine malate.
 7. The delayedgelling composition of claim 1, wherein said gel-delaying polymer iscarboxylated polymer polyaspartate (PAsp), polymalate, polyoxalate,polymalonate, polyglutarate, polyadipate, or polypimelate.
 8. Thedelayed gelling composition of claim 1, wherein said gel-delayingpolymer is PAsp and said crosslinker is Cr(III).
 9. A method ofincreasing the recovery of hydrocarbon fluids in a subterraneanformation comprising: a) injecting the delayed gelling composition ofclaim 8 into a subterranean formation, wherein said gel-delaying polymerdelays the gelation of said expandable polymeric particle by saidcrosslinker in said subterranean formation; b) injecting fluid into saidsubterranean formation to displace said delayed gelling compositiondeeper into said subterranean formation; c) waiting for said delayedgelling composition to gel; and then d) sweeping said reservoir for oiland producing said oil.
 10. The delayed gelling composition of claim 1,wherein said gel-delaying polymer is PVAS and said crosslinker isCr(III).
 11. A method of increasing the recovery of hydrocarbon fluidsin a subterranean formation comprising: a) injecting the delayed gellingcomposition of claim 10 into a subterranean formation, wherein saidgel-delaying polymer delays the gelation of said expandable polymericparticle by said crosslinker in said subterranean formation; b)injecting fluid into said subterranean formation to displace saiddelayed gelling composition deeper into said subterranean formation; c)waiting for said delayed gelling composition to gel; and then d)sweeping said reservoir for oil and producing said oil.
 12. The delayedgelling composition of claim 1, wherein said expandable polymericparticle, said at least one gel-delaying polymer, and said crosslinkertogether form a complex.
 13. The delayed gelling composition of claim12, wherein said complex comprises PVAS or PAsp as the gel-delayingpolymer and Cr(III) as the crosslinker.
 14. The delayed gellingcomposition of claim 12, wherein said expandable polymeric particlecomprises a copolymer of about 95 mole percent acrylamide and about 5mole % sodium acrylate.
 15. A method of increasing the recovery ofhydrocarbon fluids in a subterranean formation comprising: a) injectingthe delayed gelling composition of claim 14 into a subterraneanformation, wherein said gel-delaying polymer delays the gelation of saidexpandable polymeric particle by said crosslinker in said subterraneanformation; b) injecting fluid into said subterranean formation todisplace said delayed gelling composition deeper into said subterraneanformation; c) waiting for said delayed gelling composition to gel; andthen d) sweeping said reservoir for oil and producing said oil.
 16. Thedelayed gelling composition of claim 1, wherein said expandablepolymeric particle comprises a copolymer of about 95 mole percentacrylamide and about 5 mole % sodium acrylate.
 17. A method ofincreasing the recovery of hydrocarbon fluids in a subterraneanformation comprising: a) injecting the delayed gelling composition ofclaim 16 into a subterranean formation, wherein said gel-delayingpolymer delays the gelation of said expandable polymeric particle bysaid crosslinker in said subterranean formation; b) injecting fluid intosaid subterranean formation to displace said delayed gelling compositiondeeper into said subterranean formation; c) waiting for said delayedgelling composition to gel; and then d) sweeping said reservoir for oiland producing said oil.
 18. A method of increasing the recovery ofhydrocarbon fluids in a subterranean formation comprising: a) injectingthe delayed gelling composition of claim 1 into a subterraneanformation, wherein said gel-delaying polymer delays the gelation of saidexpandable polymeric particle by said crosslinker in said subterraneanformation; b) injecting fluid into said subterranean formation todisplace said delayed gelling composition deeper into said subterraneanformation; c) waiting for said delayed gelling composition to gel; andthen d) sweeping said reservoir for oil and producing said oil.